The present invention relates to invert emulsion drilling fluids for use in subterranean applications, and, in particular, invert emulsion drilling fluids having extended emulsion stability and reduced barite sag potential.
A drilling fluid or drilling mud is a designed fluid that is circulated through a wellbore to facilitate a drilling operation. Functions of a drilling fluid can include, without limitation, removing drill cuttings from the wellbore, cooling and lubricating the drill bit, aiding in the support of the drill pipe and the drill bit, and providing a hydrostatic head to maintain integrity of the wellbore walls and preventing blowouts from occurring.
It is often desirable to change the density of a drilling fluid to maintain pressure balance within a wellbore and keep the wellbore stable. Changing the density is usually accomplished by adding a weighting agent to the drilling fluid. Often, the weighting agent is barite (barium sulfate), sometimes spelled baryte. Barite is an insoluble material, and additional stabilizers are usually added to the drilling fluid to maintain the salt in a suspended state. Stabilizers can include, for example, thickeners, viscosifying agents, gelling agents and the like. Use of stabilizers can be problematic if they increase the viscosity of the drilling fluid so much that effective pumping into the wellbore becomes difficult.
In lower viscosity drilling fluids, even in the presence of added stabilizers, barite can begin to settle from the drilling fluid in a condition known as “barite sag.” Other solid weighting agents can also experience sag. As used herein, the term “barite sag” refers to a slow settling of barite or other solid weighting agent in a drilling fluid. Barite sag is undesirable because it can lead to an uneven fluid density in the wellbore and altered well performance. Barite sag can be particularly problematic in cases where the drilling fluid cannot be effectively sheared before being pumped downhole. For example, barite sag can occur during transport of a drilling fluid to an offshore drilling platform. In other instances, barite sag can occur downhole when the drilling fluid spends a longer than usual time downhole or there are inadequate downhole shearing forces. In extreme cases, barite sag can deposit a bed of barite on the low side of the wellbore, eventually leading to stuck pipe and possible abandonment of the wellbore.
The difference in a drilling fluid's surface density at the well head and the density while pumping or circulating downhole is typically referred to as the equivalent circulating density (ECD). Several drilling fluids having low ECDs have been developed that contain organophilic clay or organolignite additives. As used herein, the term “organophilic clay” refers to clays that have been treated with a cationic surfactant (e.g., a dialkylamine cationic surfactant or a quaternary ammonium compound) or like surface treatments. Organolignite additives have been prepared in a like manner. Organophilic clays swell in non-polar organic solvents, thereby forming open aggregates that are believed to be a suspending structure for barite and other solid weighting agents in invert emulsion drilling fluids containing these agents. Although such additives are effective at mediating barite sag in many cases, exposure of organophilic clays, in particular, to drill cuttings can alter the performance of the drilling fluid. In particular, organophilic clays prevent the formation of ideal or near ideal thixotropic fluids that are initially viscous but then thin at a later time.
Drilling fluids not containing organophilic clays or organolignite additives can have emulsion structures that are sensitive to low concentrations of solids therein. In these cases, a minimum concentration of solids can be required to achieve adequate emulsion stability over time. Many drilling applications rely upon the downhole introduction of solids into the drilling fluid in the form of drill cuttings in order to stabilize the drilling fluid's emulsion structure. In these cases, the introduction of ˜2-3% drill cutting solids is typically considered necessary to maintain downhole emulsion stability. Although downhole introduction of drill cutting solids provides satisfactory performance in many cases, there are notable exceptions when this is not the case. In some instances, drilling operations may not incorporate sufficient amounts of drill cutting solids into the drilling fluid to achieve satisfactory emulsion stability. In other instances, the drill cutting solids may not be of the correct type to achieve satisfactory emulsion stability. For example, sand formations and salt formations can provide drill cutting solids that fail to satisfactorily stabilize the drilling fluid's emulsion structure. In still other instances, the drilling fluid may experience significant sag during delivery to a drilling site.